A new US government management plan clears the way for oil and gas drilling on land that used to be off limits as part of a sprawling national monument in Utah before President Donald Trump downsized the protected area 2 years ago. Mosaic’s technology uses chemistry to remove carbon dioxide from emissions sources, and the two firms will be looking at how to scale it for industrial use. Scientists have discovered a way to extract hydrogen from oil without releasing greenhouse gases—a move they've hailed as a "silver bullet" for climate issues. The 33-month project will compare emissions data collected by terrestrial sensors to GHGSat's combined satellite and aircraft measurements. This paper highlights the results of a test campaign for a tool designed to predict the short-term trends of energy-efficiency indices and optimal management of a production plant. Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.” Using direct air capture in the near-term is critical if the technology is going to be affordable at a truly large scale in the coming decades. Enhanced oil recovery is the most-economic way to do that.
The well will immediately be brought on production and is expected to flow at more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said. Leaders from two large US onshore rig contractors said their expectations that the rig-count slide would hit a second-quarter bottom were off and are now refraining from making new predictions as to when it will end. The green light for Santos Energy’s drilling program in the McArthur Basin comes after a moratorium on hydraulic fracturing in the Northern Territory was lifted in 2018. The UK shale operator will move forward with fracturing and testing its second well at its Lancashire site despite strict constraints on induced seismicity that hampered fracturing work on its first well. Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers.
Rastogi, Ayush (Colorado School of Mines) | Agarwal, Karn (Liberty Oilfield Services) | Lolon, Ely (Liberty Oilfield Services) | Mayerhofer, Mike (Liberty Oilfield Services) | Oduba, Oladapo (Liberty Oilfield Services)
Artificial Neural Network (ANN) has been used by the petroleum industry to identify key well performance drivers since the 1990's. There is usually an inverse relationship between model accuracy and model interpretability—the more interpretable a model is, the more likely it is to underperform, which is a common issue with simple linear-based regression models. Without a priori assumptions regarding the relationships between response and predictor variables, ANN has successfully been used for solving nonlinear problems.
Two field production and completion databases compiled in the DJ (Niobrara) and Permian (Wolfcamp B) basins were analyzed. The objective of this paper is to focus on the inference aspect of the ANN model, rather than just reporting the model prediction results. In order to leverage neural networks as a computation tool, a detailed pre-processing workflow is recommended which improves understanding of the impact of geology, reservoir, and completion parameters on well production. The paper emphasizes the importance of data normalization, feature selection, and outlier detection as well as their implications on prediction accuracy. Self-organizing maps are used as a multi-dimensional scaling tool for unsupervised learning to preserve topography of the dataset.
Results demonstrate that using a large Permian dataset (~3,000 wells), the ANN model explains 71% of the variance in production and does not overfit when the analysis accounts for feature selection and influential points. Using a smaller DJ dataset (<400 wells), the ANN model overfits significantly even though the model explains a higher percentage of the variation in production (78%). Using Root Mean Square Error (RMSE) as an accuracy metric for the regression model, the ANN model reduces the RMSE compared to the conventional linear model. The paper reveals the misconception of using neural networks for sparse datasets. The paper also presents key well performance indicators that can be used for a quick evaluation to determine the most economical completion methods.
A pressure pumping unit stands ready for water injections into a parent wellhead to prevent damage from frac hits in the North Fork oil field of North Dakota. Frac hits were once a painful cost of doing business for Abraxas Petroleum. But today, the San Antonio, Texas-based shale producer has softened the blows dealt by this widespread and challenging problem. Its approach, called “active well defense,” has been put to the test amid the rolling hills of the company’s North Fork oil field in McKenzie, North Dakota. Instead, active well defense is designed to prevent temporary, yet costly, production stoppages caused by unabated frac hits filling parent wells with sand.
In the Alaskan North Slope field of Nikaitchuq, the standard shut-down strategy of oil producers was to inject warm diesel inside the tubing of the wells for freeze prevention of the tubing. The procedure requires that a Gas Lift Valve (Shear Orifice Valve) located at 2,000 ft be ruptured to displace the tubing fluid inside the annulus. It was desired to evaluate whether this procedure could be avoided to reduce both operational risk and costs associated with this strategy.
An evaluation was performed using a transient fluid-dynamic simulator based on oil producers. Based on geothermal gradient acquired by DTS fiber optic technology and considering the salinity of formation water, the depth of the tubing under freezing risk was defined. Simulations were performed for both the rate of cooling of the produced fluids in the tubing and the time required to reach ice formation conditions.
In the paper, we will show that the sweeping effect of gas during production does not allow for water accumulation at the x-mas tree and surface piping. In addition, the vertical geometry in the tubing results that any water present falls below the permafrost line during shut-in conditions. As no bulk water is present in the well inside of the ice stability region, the risk of a blockage from ice is not present during a planned shutdown and the previous preservation strategy is not required.
The change in the standard operating procedure for planned shutdowns was successfully applied, leading to a marked reduction of costs and reduced down-time with a consequential recovery of otherwise lost production.
Liberty Island would resemble Hilcorp’s Northstar Island (pictured) located 31 miles to the northwest. Hilcorp has received long-awaited federal approval for its plan to build a 9-acre gravel island for drilling and production in the shallow waters of the Beaufort Sea. Liberty Island, to be located 5 miles offshore in 19 ft of water, would be the first oil and gas production facility in federal waters off Alaska. The industry has explored building a site there for more than 3 decades. It would be the fifth artificial island to operate off Alaska, with Hilcorp’s Northstar and Endicott Islands, Eni’s Spy Island, and Caelus Energy’s Oooguruk Island sitting in state waters.
SPE 101 is intended for young professionals who aim to maximize the value of their SPE membership. This section will showcase programs that make SPE an indispensable tool for technical growth and career development. We invite you to take full advantage of what SPE has to offer and to participate in SPE's continuing evolution. Most of us sooner or later will encounter a work-related challenge our immediate network of colleagues and contacts cannot help with. You may be considering a difficult operation, with no consensus on how to proceed.
One of the biggest challenges in designing squeeze treatments is ensuring appropriate chemical placement along the completion interval. Generally, the chemical slug is bull-headed; therefore, in long horizontal wells and/or crossflow wells, exposing the chemical to all the completion intervals might be difficult. In this paper we introduce a method to evaluate placement efficiency. If placement is inadequate, some sections of the well will be unprotected, resulting in an undesirable situation: the well may appear to be protected because the inhibitor return concentrations measured at surface are above the threshold, but there is a loss of production due to scale deposition in areas of the well not contacted by chemical. In these circumstances inhibitor placement can be accurately determined by production logging, but this can be prohibitively expensive. An alternative is to use tracers to evaluate the layer flow rate distribution, and therefore quantify chemical placement. The objective of this paper is to determine if a tracer package could be deployed as part of a squeeze treatment in challenging wells, in particular in the overflush stage. If there are zones in the wellbore at different pressures, then producing the tracer back in steps at different rates will result in the tracer return concentration profile having characteristic features that can be interpreted to estimate chemical placement.
Two three layer cases with crossflow are considered. In both cases, a tracer package was included in the overflush, and the resulting return profiles showed clearly the desired features. The main advantage of this approach is that there is no significant increase in the operational expense. The only additional expense will be the cost of the specific tracer and the subsequent analysis. It is envisaged that the cost is less than 5% of the total squeeze treatment cost. The results of this novel multi-rate post squeeze production stage following injection of tracer demonstrate the feasibility of including such a tracer package in a squeeze treatment. Data collected may then be used to optimise the design of subsequent treatments, to ensure that appropriate placement is achieved by rate control or by diversion, if necessary.
Rock, Alexander (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Hoffmann, Eugen (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
This work provides an extensive review on Low Salinity Water Flooding (LSWF) recovery mechanisms, as well as an evaluation of its synergies with Polymer Flooding (PF). Thereby, a critical state-of-the-art evaluation on LSWF and PF mechanisms is combined with selective laboratory experiments, performed to illustrate the observations and findings. This evaluation can be used as a guidance to understand the expected behavior of both processes when applied in combination.
The work presented here comprises two main steps: 1) Comprehensive review of the mechanisms responsible of oil recovery in each process and 2) Predefined secondary and tertiary mode flooding experiments. First, oil recovery mechanisms associated to LSWF and PF have been analyzed in detail. Second, different field cases were compared in order to draw the main conclusions with regards to performance and recovery factors. This also helped to define the synergies of LSWF and PF in terms of technical and economic efficiency. Finally, secondary and tertiary mode experiments were performed to evaluate the feasibility of applying both processes.
Despite of the over 15 mechanisms reported in the literature for LSWF, six main mechanisms were identified that contributes to oil recovery. Mechanisms are described as: 1) Wettability alteration 2) Multi-ion exchange, 3) Fine migration, 4) Salting-in, 5) Double-Layer-Expansion and, 6) Other mechanisms, such as osmotic pressure and IFT reduction. Thereby, wettability alteration and fine migration have the highest significance. On the other hand, PF mechanisms were found to be: 1) Viscous fingering reduction, 2) Enhanced flow between layers, 3) Pull-out effects, 4) Shear thickening/elastic turbulence and, 5) Relative permeability reduction. LSWF field cases revealed incremental recoveries of up to 13% OOIP whereas synergies between LSWF and PF yielded to an additional recovery of 15% OOIP, underlining the potential of the combination of both EOR technologies. Selective LSWF-PF experiments performed in sandstones core-plugs in this work, allowed the verification of the additional recoveries reported in the literature. Tertiary flooding with solely LSWF, showed a lower recovery than tertiary LSWF-PF flooding. Moreover, this observation confirms the potentiality of polymer-combined LSWF in sandstones. Additionally, with the combined processes, a lower polymer concentration was required than applying a typically designed polymer flooding. This can be translated to an economic benefit for field applications.
Tertiary mode flooding experiments in sandstones and the analysis of field cases provided clear evidence of the advantages of LSWF-PF. This could yield that the processes -when applied in tandem- become a leading EOR strategy, ensuring the extension of the reservoir lifetime. Moreover, fellow researchers can benefit because the work provides a comprehensive review of Low Salinity Water Flooding and Polymer Flooding mechanisms. To the authors understanding, literature is currently lacking of such a review.
Data from this well fire in the Rumaila field set during the invasion of Iraq in 2003 was one of the Boots & Coots jobs included in the study of well fire efficiency. An oil well blowout can burn like a rocket, which can be a good thing. Burning leaves little or no oil behind, according to a recent study (SPE 189610). The study has been used to make a case for an oil spill response plan now before regulators to develop a field with more than 100 million bbl of reserves in the Beaufort Sea. Plan approval is one of the remaining barriers facing Hilcorp, the operator in a partnership with BP to develop the Liberty field.